In order to provide adequate well control and to satisfy the statutory safety requirements of many jurisdictions around the world, most operating companies adopt the principle of ensuring that at least two independently verified barriers are in place at all times during the construction or suspension of wells. The term “barrier” as used throughout this specification refers to a physical measure that is capable of forming a seal so as to prevent an uncontrolled release or flow of fluid from the pressure side of the barrier. Well construction operations include all activities from the time the well is drilled until the well is completed ready for production by installing a production flow control device. The most commonly used production flow control devices are typically referred to as “christmas trees”.
During well construction operations when at least two barriers may be installed and verified in the well bore, the well may be referred to as being “suspended”. A well cannot be temporarily suspended or permanently abandoned without ensuring that the required at least two independently verified barriers are in place.
From time to time during the life of a producing well, remedial action such as repairs or maintenance are required. Such remedial action operations, including interventions, are referred to throughout this specification as “workover operations”. When it is required to perform a workover operation, it is again typically a statutory safety requirement of many jurisdictions around the world, that at least two independently verified barriers be in place at all times.
Frequently, a plurality of wells are constructed to tap into a given oil and/or gas reservoir or formation. Depending on the geology of a given site, as well as scheduling requirements, it is common for one or more of the wells to be temporarily suspended for a period of time. These suspended wells may be re-entered and completed as producing or development wells at a later date. At some sites, each well is sequentially drilled and completed. At other sites, the well construction operations may be “batched”. When batching is used, the well construction processes are carried out in discrete steps. For example, a first sequence of steps is conducted on a number of wells, followed by a second sequence of steps being conducted on those wells. The process is repeated until each well has been completed. Batching is used to allow well construction operations to be optimised logistically or for completion operations to be performed using a different, typically smaller, rig or vessel than that used for drilling.
Typically, the first step in the construction of a well involves the drilling of a well-bore. FIG. 1 illustrates an example of a typical sub-sea well 10 that has been drilled but not yet suspended. With reference to FIG. 1, the well 10 is provided with a well-head 11 and a guide base 12. A sub-sea BOP stack 40 as well as its associated marine riser 42 is positioned on the well-head 11 to provide well control during the drilling operation. Subsequently, well control is achieved by placement of at least two independently verified barriers elsewhere.
Drilling continues to extend the well bore and additional casing strings are installed sequentially in the well 10. In the illustrated example of FIG. 1, a first casing string 14 with a nominal size of 30 inches is installed first. A second casing string 16 with a nominal size of 20 inches is run with the well-head 11 and cemented into position. A third casing string 18 having a nominal size of 13⅜ inches is provided within the second casing string 16. A fourth and final casing string 20 having a nominal size of 9⅝ inches is provided within the third casing 18.
For platform wells, the casing strings can extend above the mudline or sea-floor to a rig floor 46 or cellar deck 44 of the platform. The well-head is typically located at an uppermost end of the well bore at the mud line for sub-sea wells, at platform level for platform wells or at ground level for land wells.
After the required number of casing strings has been installed, it is common, but not essential, to install a liner 22 which is a string of pipe which does not extend to the surface. The liner is typically suspended from a liner hanger 24 installed inside the lowermost casing string 20.
During drilling of a well, it is common to maintain a sufficient hydraulic head of fluid in the well-bore to provide an over-balance relative to the expected pressure of the reservoir or formation into which the well is being drilled. When the well is to be suspended, other barriers must be provided.
The requirement for a second barrier to be in place at all times is satisfied during drilling and casing operations by positioning a blow-out preventer (BOP) stack the top of the well. Some of the casing strings, the liner, the liner hanger, the first barrier and the completion string are all run through the bore of the BOP stack. For sub-sea wells not using a surface BOP stack, the down-hole equipment must also be run through the bore of the marine riser associated with the sub-sea BOP stack.
To accommodate the running of the down hole equipment through the BOP stack, the BOP stack typically has a nominal internal bore diameter of 18¾ inches and is thus an extremely large piece of equipment. For sub-sea wells, the time taken to run and/or retrieve the BOP stack depends upon the distance between the water-line and the mudline, and in deep water may take several days. The economic viability of offshore operations directly depends on the time taken to perform the various construction operations. Thus, the running and retrieval of a BOP stack is considered to be one of the costliest operations associated with sub-sea well construction.
Using prior art methods, a first barrier, “B1” is typically set above the reservoir or formation as illustrated in FIG. 2. If the well is to be suspended, a second barrier, “B2”, must be established and verified elsewhere in the well-bore before the BOP stack can be removed.
It is a longstanding and well-accepted industry practice to position the second required barrier, B2 towards an uppermost end of the well-bore and typically in the well-head 11 or the uppermost end of the final casing string 20 with reference to FIG. 2. This second barrier, B2 was traditionally in the form of a cement plug. More recently, however, the use of cement plugs has been replaced by the use of mechanical barriers to overcome some of the cleanliness problems associated with removal of the cement plugs. The types of mechanical barriers being used as the second barrier include wireline or drill-pipe retrievable devices such as plugs and packers.
There are several factors that motivate operating companies to place the second barrier towards the top of the well. One of the key drivers is the reduced cost in running and/or retrieving the second barrier when it is placed towards the top of the well-bore. It is also widely accepted that the first and second barrier should be placed as far apart as possible to facilitate independent verification of each barrier. If the first and second barriers are set in close proximity it has been considered prohibitively difficult to independently verify the integrity of the second barrier. The integrity of the first barrier is verified by filling the well-bore with a fluid and pressurising the column of fluid to a given pressure. Due to the compressibility of the fluid or entrapped gas, the pressure typically drops over a short period of time before levelling off. If the barrier is leaking, the pressure does not level off.
This procedure is repeated after the second barrier is installed. When the second barrier is positioned in the uppermost end of the well-bore, the quantity of fluid need to pressurise the well-bore during pressure testing is greatly reduced if the second barrier has integrity. It is thus easy to detect if fluid is passing this upper barrier.
To prepare the well for production, a “completion string” is installed in the well bore. The term “completion string” as used throughout this specification refers to the tubing and equipment that is installed in the well-bore to enable production from a formation. The upper end of the completion string typically terminates in and includes a tubing hanger from which the completion string is suspended. The completion string typically includes an annular production packer positioned towards the lowermost end of the completion string. The packer isolates the annulus of the well-bore from the completion string, the annulus being the space through which fluid can flow between the completion string and the casing string and/or liner. The lowermost end of the completion string is commonly referred to as a “tail pipe”.
When the well is ready for production, the oil, water and/or gas passes through the liner or casing and through the completion string to a production flow control device located at or above the well-head.
The well suspension methods of the prior art require removal of the upper barrier before the well can be completed. To provide the required second barrier, the BOP stack must be re-installed above the well in what has been a long-standing, commonly employed industry practice. The BOP stack cannot be removed until at least two barriers are established elsewhere. The requirement to install a BOP stack generates a number of problems. Firstly, the operations that must be performed prior to removal of the BOP stack are limited to tooling which can pass through the internal diameter of the bore of the BOP stack. Secondly, the bore of the BOP stack (and its associated marine riser for sub-sea wells) may contain debris such as swarf, cement and/or cuttings in the rams or annular cavities of the BOP stack, as well as debris in the drill and/or choke lines and/or corrosion product in the marine riser. Consequently, one of the problems with current well construction practice is the high level of debris that accumulates as the completion string and other equipment pass through the bore of the BOP stack and/or its associated marine riser. Thirdly, the need to run or recover the BOP stack during well construction operations can add considerable expense to the cost of these operations with costs being directly proportional to the amount of rig time that must be allocated to these operations.
There is a need for less time-consuming and therefore less expensive method of well construction.
It will be clearly understood that, although prior art use is referred to herein, this reference does not constitute an admission that any of these form a part of the common general knowledge in the art, in Australia or in any other country.
In the summary of the invention and the description and claims which follow, except where the context requires otherwise due to express language or necessary implication, the word “comprise” or variations such as “comprises” or “comprising” is used in an inclusive sense, i.e. to specify the presence of the stated features but not to preclude the presence or addition of further features in various embodiments of the invention.